LECTURE NOTES
ON
POWET PLANT CONTROL AND INSTRUMENTATION
B.Tech VII Sem (IARE-R16)
By
Dr. M. LAXMIDEVI RAMANAIAH ASSOCIATE PROFESSOR
DEPARTMENT OF ELECTRICAL AND ELECTRONICS ENGINEERING
INSTITUTE OF AERONAUTICAL ENGINEERING
(Autonomous)
DUNDIGAL, HYDERABAD - 500 043
UNIT-I
OVERVIEW OF POWER GENERATION
INTRODUCTION:
The utility electricity sector in India has one national grid with an installed capacity of 57.875 GW as of 30 June 2019. Renewable power plants, which also include large hydroelectric plants, constitute 34.86% of India's total installed capacity. During the 2017-18 fiscal year, the gross electricity generated by utilities in India was 1,303.49 TWh and the total electricity generation (utilities and non utilities) in the country was 1,486.5 TWh. The gross electricity consumption during the 2017-18 fiscal year was 1,149 kWh per capita. India is the world's third largest producer and third largest consumer of electricity. In the 2015-16 fiscal year, electric energy consumption in agriculture was recorded as being the highest (17.89%) worldwide.
The per capita electricity consumption is low compared to most other countries despite India having a cheaper electricity tariff.
India has a surplus power generation capacity but lacks adequate infrastructure for supplying electricity to all who need it. In order to address the lack of adequate electricity supply to all the people in the country by March 2019, the Government of India launched a program called
"Power for All". This program is intended to ensure continuous and uninterrupted electricity supply to all households, industries and commercial establishments by creating and improving the necessary infrastructure. It is a joint collaboration between the Government of India and its constituent states, who will share funding and create overall economic growth.
India's electricity sector is dominated by fossil fuels, and in particular, coal, which during the 2017-18 fiscal year produced about three-fourths of the country's electricity. However, the government is pushing for increased investment in renewable energy. The National Electricity Plan of 2018, prepared by the Government of India, states that the country does not need additional non-renewable power plants in the utility sector until 2027, with the commissioning of 50,025 MW coal-based power plants under construction and achieving 275,000 MW total installed renewable power capacity after the retirement of nearly 48,000 MW old coal-fired plants.
STEAM POWER PLANT:
A thermal power station is a power plant in which the prime mover is steam driven.
Water is heated, turns into steam and spins a steam turbine which drives an electrical generator. After it passes through the turbine, the steam is condensed in a condenser and recycled to where it was heated; this is known as a Rankine cycle. The greatest variation in the design of thermal power stations is due to the different fuel sources. Some prefer to use the term energy center because such facilities convert forms of heat energy into electricity.
Some thermal power plants also deliver heat energy for industrial purposes, for district heating, or for desalination of water as well as delivering electrical power. A large proportion of CO2 is produced by the worlds fossil fired thermal power plants; efforts to reduce these outputs are various and widespread.
The four main circuits one would come across in any thermal power plant layout are
Coal and Ash Circuit
Air and Gas Circuit
Feed Water and Steam Circuit
Cooling Water Circuit
Coal and Ash Circuit:
Coal and Ash circuit in a thermal power plant layout mainly takes care of feeding the boiler with coal from the storage for combustion. The ash that is generated during combustion is collected at the back of the boiler and removed to the ash storage by scrap conveyors. The combustion in the Coal and Ash circuit is controlled by regulating the speed and the quality of coal entering the grate and the damper openings.
Air and Gas Circuit
Air from the atmosphere is directed into the furnace through the air preheated by the action of a forced draught fan or induced draught fan. The dust from the air is removed before it enters the combustion chamber of the thermal power plant layout. The exhaust gases from the combustion heat the air, which goes through a heat exchanger and is finally let off into the environment.
Feed Water and Steam Circuit
The steam produced in the boiler is supplied to the turbines to generate power. The steam that is expelled by the prime mover in the thermal power plant layout is then condensed in a condenser for re-use in the boiler. The condensed water is forced through a pump into the feed water heaters where it is heated using the steam from different points in the turbine. To make up for the lost steam and water while passing through the various components of the thermal power plant layout, feed water is supplied through external sources. Feed water is purified in a purifying plant to reduce the dissolve salts that could scale the boiler tubes.
Cooling Water Circuit: The quantity of cooling water required to cool the steam in a thermal power plant layout is significantly high and hence it is supplied from a natural water source like a lake or a river. After passing through screens that remove particles that can plug the condenser tubes in a thermal power plant layout, it is passed through the condenser where the steam is condensed. The water is finally discharged back into the water source after cooling. Cooling water circuit can also be a closed system where the cooled water is sent through cooling towers for re-use in the power plant. The cooling
water circulation in the condenser of a thermal power plant layout helps in maintaining a low pressure in the condenser all throughout.
All these circuits are integrated to form a thermal power plant layout that generates electricity to meet our needs.
HYDEL POWER PLANT
Hydroelectric power plants convert the hydraulic potential energy from water into electrical energy. Such plants are suitable were water with suitable head are available.
The layout covered in this article is just a simple one and only cover the important parts of hydroelectric plant. The different parts of a hydroelectric power plant are
(1) Dam: Dams are structures built over rivers to stop the water flow and form a reservoir.
The reservoir stores the water flowing down the river. This water is diverted to turbines in power stations. The dams collect water during the rainy season and stores it, thus allowing for a steady flow through the turbines throughout the year. Dams are also used for controlling floods and irrigation. The dams should be water-tight and should be able to withstand the pressure exerted by the water on it. There are different types of dams such as arch dams, gravity dams and buttress dams. The height of water in the dam is called head race.
(2) Spillway: A spillway as the name suggests could be called as a way for spilling of water from dams. It is used to provide for the release of flood water from a dam. It is used to prevent over toping of the dams which could result in damage or failure of dams.
Spillways could be controlled type or uncontrolled type. The uncontrolled types start releasing water upon water rising above a particular level. But in case of the controlled type, regulation of flow is possible.
(3) Penstock and Tunnel: Penstocks are pipes which carry water from the reservoir to the turbines inside power station. They are usually made of steel and are equipped with gate systems. Water under high pressure flows through the penstock. A tunnel serves the same purpose as a penstock. It is used when an obstruction is present between the dam and power station such as a mountain.
(4) Surge Tank: Surge tanks are tanks connected to the water conductor system. It serves the purpose of reducing water hammering in pipes which can cause damage to pipes. The sudden surges of water in penstock are taken by the surge tank, and when the water requirements increase, it supplies the collected water thereby regulating water flow and pressure inside the penstock.
(5) Power Station: Power station contains a turbine coupled to a generator. The water brought to the power station rotates the vanes of the turbine producing torque and rotation of turbine shaft. This rotational torque is transferred to the generator and is converted into
electricity. The used water is released through the tail race. The difference between head race and tail race is called gross head and by subtracting the frictional losses we get the net head available to the turbine for generation of electricity.
NUCLEAR POWER PLANT:
Nuclear power is the use of sustained Nuclear fission to generate heat and do useful work. Nuclear Electric Plants, Nuclear Ships and Submarines use controlled nuclear energy to heat water and produce steam, while in space, nuclear energy decays naturally in a radioisotope thermoelectric generator. Scientists are experimenting with fusion energy for future generation, but these experiments do not currently generate useful energy. Nuclear power provides about 6% of the world's energy and 13–14% of the world's electricity, with the U.S., France, and Japan together accounting for about 50% of nuclear generated electricity. Also, more than 150 naval vessels using nuclear propulsion have been built.
Just as many conventional thermal power stations generate electricity by harnessing the thermal energy released from burning fossil fuels, nuclear power plants convert the energy released from the nucleus of an atom, typically via nuclear fission.
Nuclear reactor technology
When a relatively large fissile atomic nucleus (usually uranium-235 or plutonium-239) absorbs a neutron, a fission of the atom often results. Fission splits the atom into two or more smaller nuclei with kinetic energy (known as fission products) and also releases gamma radiation and free neutrons.[59] A portion of these neutrons may later be absorbed by other fissile atoms and create more fissions, which release more neutrons, and so on.This nuclear chain reaction can be controlled by using neutron poisons and neutron moderators to change the portion of neutrons that will go on to cause more fissions.[60] Nuclear reactors generally have automatic and manual systems to shut the fission reaction down if unsafe conditions are detected. Three nuclear powered ships, (top to bottom) nuclear cruisers USS Bainbridge and USS Long Beach with USS Enterprise the first nuclear powered aircraft carrier in 1964. Crew members are spelling out Einstein's mass-energy equivalence formula E = mc2 on the flight deck.
There are many different reactor designs, utilizing different fuels and coolants and incorporating different control schemes. Some of these designs have been engineered to meet a specific need. Reactors for nuclear submarines and large naval ships, for example, commonly use highly enriched uranium as a fuel. This fuel choice increases the reactor's power density and extends the usable life of the nuclear fuel load, but is more expensive and a greater risk to nuclear proliferation than some of the other nuclear fuels.
A number of new designs for nuclear power generation, collectively known as the Generation IV reactors, are the subject of active research and may be used for practical power generation in the future. Many of these new designs specifically attempt to make fission reactors cleaner, safer and/or less of a risk to the proliferation of nuclear weapons. Passively safe plants (such as the ESBWR) are available to be built and other designs that are believed to be nearly fool-proof are being pursued. Fusion reactors, which may be viable in the future, diminish or eliminate many of the risks associated with nuclear fission. There are trades to be made between safety, economic and technical properties of different reactor designs for particular applications. Historically these decisions were often made in private by scientists, regulators and engineers, but this may be considered problematic, and since Chernobyl and Three Mile Island, many involved now consider informed consent and morality should be primary considerations.
Cooling system
A cooling system removes heat from the reactor core and transports it to another area of the plant, where the thermal energy can be harnessed to produce electricity or to do other useful work. Typically the hot coolant will be used as a heat source for a boiler, and the pressurized steam from that boiler will power one or more steam turbine driven electrical generators.
Flexibility of nuclear power plants
It is often claimed that nuclear stations are inflexible in their output, implying that other forms of energy would be required to meet peak demand. While that is true for the vast majority of reactors, this is no longer true of at least some modern designs. Nuclear plants are routinely used in load following mode on a large scale in France. Unit A at the German Biblis Nuclear Power Plant is designed to in- and decrease his output 15 % per minute between 40 and 100 % of it's nominal power. Boiling water reactors normally have load-following capability, implemented by varying the recirculation water flow.
SOLAR POWER PLANT
Solar power plants use the sun's rays to produce electricity. Photovoltaic plants and solar thermal systems are the most commonly used solar technologies today.
1. Photovoltaic plants: A photovoltaic cell, commonly called a solar cell or PV, is a technology used to convert solar energy directly into electricity. A photovoltaic cell is usually made from silicon alloys. Particles of solar energy, known as photons, strike the surface of a photovoltaic cell between two semiconductors. These semiconductors exhibit a property known as the photoelectric effect, which causes them to absorb the photons and release electrons. The electrons are captured in the form of an electric current - in other words, electricity.
2. Solar thermal power plants : A solar thermal plant generates heat and electricity by concentrating the sun's energy. That in turn builds steam that helps to feed a turbine and generator to produce electricity.
There are three types of solar thermal power plants:
a) Parabolic troughs: This is the most common type of solar thermal plant. A "solar field" usually contains many parallel rows of solar parabolic trough collectors. They use parabola-shaped reflectors to focus the sun at 30 to 100 times its normal intensity.
The method is used to heat a special type of fluid, which is then collected at a central location to generate high-pressure, superheated steam.
b) Solar power tower : This system uses hundreds to thousands of flat sun-tracking mirrors called heliostats to reflect and concentrate the sun's energy onto a central receiver tower. The energy can be concentrated as much as 1,500 times that of the energy coming in from the sun.
A test solar power tower exists in Juelich in the western German state of North-Rhine Westphalia. It is spread over 18,000 square meters (194,000 square feet) and uses more than 2,000 sun-tracking mirrors to reflect and concentrate the sun's energy onto a 60-meter-high (200 foot high) central receiver tower.
The concentrated solar energy is used to heat the air in the tower to up to 700 degrees Celsius (1,300 degrees Fahrenheit). The heat is captured in a boiler and is used to produce electricity with the help of a steam turbine. Solar thermal energy collectors work well even in adverse weather conditions. They're used in the Mojave Desert in California and have withstood hailstorms and sandstorms.
c) Solar pond: This is a pool of saltwater which collects and stores solar thermal energy. It uses so-called salinity-gradient technology.
Basically, the bottom layer of the pond is extremely hot - up to 85 degrees Celsius - and acts as a transparent insulator, permitting sunlight to be trapped from which heat may be withdrawn or stored for later use. This technology has been used in Israel since 1984 to produce electricity.
When the wind, a natural form of energy, is capable of creating electricity or a mechanical force, this is wind power.
Rather like windmills (a name they are sometimes given), wind turbines use the power of the wind, which they transform into electricity. The speed of the wind rotates the blades of a rotor (between 10 and 25 rpm), producing kinetic energy. The rotor then drives a generator that converts the mechanical energy into electricity. A weathervane and a robot orient the nacelle so that the blades are positioned optimally with regard to the wind. Each wind turbine is made up of a mast, which can be between 20 and 100 meters tall, depending on the power of the machine,
which supports the rotor, generally consisting of three blades, and the nacelle, which houses the generator and the electrical and mechanical gear. The wind turbines are connected to the power grid via a transformer housed at the base of the mast. The electricity generated is generally raised to the grid voltage (20 kV). It is then transferred via a substation before being injected into the distribution or transmission networks.
The power of modern onshore wind turbines is in excess of 3 MW. Wind turbines are designed for wind speeds of between 14 and 90 kph. When the wind speed is faster, a braking mechanism automatically stops the wind turbine, ensuring the safety of the installation and minimizing wear.
Modern wind turbines produce their rated output at wind speeds of around 50 kph.
The majority of wind turbines consist of three blades mounted to a tower made from tubular steel. There are less common varieties with two blades, or with concrete or steel lattice towers.
At 100 feet or more above the ground, the tower allows the turbine to take advantage of faster wind speeds found at higher altitudes.
Turbines catch the wind's energy with their propeller-like blades, which act much like an airplane wing. When the wind blows, a pocket of low-pressure air forms on one side of the blade.
The low-pressure air pocket then pulls the blade toward it, causing the rotor to turn. This is called lift. The force of the lift is much stronger than the wind's force against the front side of the blade, which is called drag. The combination of lift and drag causes the rotor to spin like a propeller.
A series of gears increase the rotation of the rotor from about 18 revolutions a minute to roughly 1,800 revolutions per minute -- a speed that allows the turbine’s generator to produce AC electricity.
A streamlined enclosure called a nacelle houses key turbine components -- usually including the gears, rotor and generator -- are found within a housing called the nacelle. Sitting atop the turbine tower, some nacelles are large enough for a helicopter to land on.
Another key component is the turbine’s controller, that keeps the rotor speeds from exceeding 55 mph to avoid damage by high winds. An anemometer continuously measures wind speed and transmits the data to the controller. A brake, also housed in the nacelle, stops the rotor mechanically, electrically or hydraulically in emergencies. Explore the interactive graphic above to learn more about the mechanics of wind turbines.
Types of Wind Turbines: There are two basic types of wind turbines: those with a horizontal axis, and those with a a vertical axis.
The majority of wind turbines have a horizontal axis: a propeller-style design with blades that rotate around a horizontal axis. Horizontal axis turbines are either upwind (the wind hits the blades before the tower) or downwind (the wind hits the tower before the blades). Upwind turbines also include a yaw drive and motor -- components that turns the nacelle to keep the rotor facing the wind when its direction changes.
While there are several manufacturers of vertical axis wind turbines, they have not penetrated the utility scale market (100 kW capacity and larger) to the same degree as horizontal access turbines. Vertical axis turbines fall into two main designs:
Drag-based, or Savonius, turbines generally have rotors with solid vanes that rotate about a vertical axis.
Lift-based, or Darrieus, turbines have a tall, vertical airfoil style (some appear to have an eggbeater shape). The Windspire is a type of lift-based turbine that is undergoing independent testing at the National Renewable Energy Laboratory's National Wind Technology Center.
Wind Turbine Applications: Wind Turbines are used in a variety of applications – from harnessing offshore wind resources to generating electricity for a single home:
Large wind turbines, most often used by utilities to provide power to a grid, range from 100 kilowatts to several megawatts. These utility-scale turbines are often grouped together in wind farms to produce large amounts of electricity. Wind farms can consist of a few or hundreds of turbines, providing enough power for tens of thousands of homes.
Small wind turbines, up to 100 kilowatts, are typically close to where the generated electricity will be used, for example, near homes, telecommunications dishes or water pumping stations.
Small turbines are sometimes connected to diesel generators, batteries and photovoltaic systems. These systems are called hybrid wind systems and are typically used in remote, off- grid locations, where a connection to the utility grid is not available.
Offshore wind turbines are used in many countries to harness the energy of strong, consistent winds found off of coastlines. The technical resource potential of the winds above U.S.
coastal waters is enough to provide more than 4,000 gigawatts of electricity, or approximately four times the generating capacity of the current U.S. electric power system. Although not all of these resources will be developed, this represents a major opportunity to provide power to highly populated coastal cities. To take advantage of America’s vast offshore wind resources, the Department is investing in three offshore wind demonstration projects designed to deploy offshore wind systems in federal and state waters by 2017.
Importance of instrumentation in power generation:
The role of instrumentation in thermal power plants is like any other process plants. There are various parameters like pressure, temperature, flow, level, vibration etc which needs to be monitored and controlled in such plants. Also some modern plants have automation systems like DCS and PLC along with many interlocks. So instrumentation have an critical role in thermal power plants. Steam is mainly required for power generation, process heating and pace heating purposes. The capacity of the boilers used for power generation is considerably large compared with other boilers. Due to the requirement of high efficiency, the steam for power generation is produced at high pressures and in very large quantities. They are very large in size and are of individual design depending the type of fuel to be used.
The boilers generating steam for process heating are generally smaller in size and generate steam at a much lower pressure. They are simpler in design and are repeatedly constructed to the same design. Though most of these boilers are used for heating purposes, some, like locomotive boilers are used for power generation also. In this chapter, some simple types of boilers will be described. A steam generator popularly known as boiler is a closed vessel made of high quality steel in which steam is generated from water by the application of heat. The water receives heat from the hot gases though the heating surfaces of the boiler. The hot gases are formed by burning fuel, may be coal, oil or gas. Heating surface of the boiler is that part of the boiler which is exposed to hot gases on one side and water or steam on the other side. The steam which is collected over the water surface is taken from the boiler through super heater and then suitable pipes for driving engines or turbines or for some industrial heating purpose. A boiler consists of not only the steam generator but also a number of parts to help for the safe and efficient operation of the system as a whole. These parts are called mountings and accessories.
BOILER :
A boiler is a closed vessel in which water or other fluid is heated. The heated or vaporized fluid exits the boiler for use in various processes or heating applications.Most boilers produce steam to be used at saturation temperature; that is, saturated steam.
Superheated steam boilers vaporize the water and then further heat the steam in a superheater. This provides steam at much higher temperature, but can decrease the
overall thermal efficiency of the steam generating plant because the higher steam temperature requires a higher flue gas exhaust temperature. There are several ways to circumvent this problem, typically by providing an economizer that heats the feed water, a combustion air heater in the hot flue gas exhaust path, or both. There are advantages to superheated steam that may, and often will, increase overall efficiency of both steam generation and its utilization: gains in input temperature to a turbine should outweigh any cost in additional boiler complication and expense. There may also be practical limitations in using wet steam, as entrained condensation droplets will damage turbine blades. Superheated steam presents unique safety concerns because, if any system component fails and allows steam to escape, the high pressure and temperature can cause serious, instantaneous harm to anyone in its path. Since the escaping steam will initially be completely superheated vapor, detection can be difficult, although the intense heat and sound from such a leak clearly indicates its presence.
Superheater operation is similar to that of the coils on an air conditioning unit, although for a different purpose. The steam piping is directed through the flue gas path in the boiler furnace. The temperature in this area is typically between 1,300–1,600 degrees Celsius. Some superheaters are radiant type; that is, they absorb heat by radiation. Others are convection type, absorbing heat from a fluid. Some are a combination of the two types. Through either method, the extreme heat in the flue gas path will also heat the superheater steam piping and the steam within. While the temperature of the steam in the superheater rises, the pressure of the steam does not: the turbine or moving pistons offer a continuously expanding space and the pressure remains the same as that of the boiler.
Almost all steam superheater system designs remove droplets entrained in the steam to prevent damage to the turbine blading and associated piping.
SUPERCRITICAL BOILER:
Supercritical steam generators (also known as Benson boilers) are frequently used for the production of electric power. They operate at "supercritical pressure". In contrast to a "subcritical boiler", a supercritical steam generator operates at such a high pressure (over 3,200 psi/22.06 MPa or 220.6 bar) that actual boiling ceases to occur, and the boiler has no water - steam separation. There is no generation of steam bubbles within the water, because the pressure is above the "critical pressure" at which steam bubbles can form. It passes below the critical point as it does work in the high pressure turbine and enters the generator's condenser. This is more efficient, resulting in slightly less fuel use. The term "boiler" should not be used for a supercritical pressure steam generator, as no "boiling" actually occurs in this device.
FLUIDIZED BED BOILERS:
The major portion of the coal available in India is of low quality, high ash content and low calorific value. The traditional grate fuel firing systems have got limitations and are techno-economically unviable to meet the challenges of future. Fluidized bed combustion has emerged as a viable alternative and has significant advantages over conventional firing system and offers multiple benefits – compact boiler design, fuel flexibility, higher combustion efficiency and reduced emission of noxious pollutants such as SOx and NOx. The fuels burnt in these boilers include coal, washery rejects, rice husk, bagasse & other agricultural wastes. The fluidized bed boilers have a wide capacity range- 0.5 T/hr to over 100 T/hr.
Piping and instrumentation diagram:
A piping and instrumentation diagram (P&ID) is a detailed diagram in the process industry which shows the piping and process equipment together with the instrumentation and control devices.
A piping and instrumentation diagram (P&ID) is defined by the Institute of Instrumentation and Control as follows:
1. A diagram which shows the interconnection of process equipment and the instrumentation used to control the process. In the process industry, a standard set of symbols is used to prepare drawings of processes. The instrument symbols used in these drawings are generally based on International Society of Automation (ISA) Standard S5.1
2. The primary schematic drawing used for laying out a process control installation.
They usually contain the following information:
Mechanical equipment, including:
o Pressure vessels, columns, tanks, pumps, compressors, heat exchangers, furnaces, wellheads, fans, cooling towers, turbo-expanders, pig traps (see 'symbols' below)
o Bursting discs, restriction orifices, strainers and filters, steam traps, moisture traps, sight- glasses, silencers, flares and vents, flame arrestors, vortex breakers, eductors
Process piping, sizes and identification, including:
o Pipe classes and piping line numbers
o Flow directions
o Interconnections references
o Permanent start-up, flush and bypass lines
o Pipelines and flowlines
o Blinds and spectacle blinds
o Insulation and heat tracing
Process control instrumentation and designation (names, numbers, unique tag identifiers), including:
o Valves and their types and identifications (e.g. isolation, shutoff, relief and safety valves, valve interlocks)
o Control inputs and outputs (sensors and final elements, interlocks)
o Miscellaneous - vents, drains, flanges, special fittings, sampling lines, reducers and swages
Interfaces for class changes
Computer control system
Identification of components and subsystems delivered by others
P&IDs are originally drawn up at the design stage from a combination of process flow sheet data, the mechanical process equipment design, and the instrumentation engineering design.
During the design stage, the diagram also provides the basis for the development of system control schemes, allowing for further safety and operational investigations, such as a Hazard and operability study (HAZOP). To do this, it is critical to demonstrate the physical sequence of equipment and systems, as well as how these systems connect.
P&IDs also play a significant role in the maintenance and modification of the process after initial build. Modifications are red-penned onto the diagrams and are vital records of the current plant design.
They are also vital in enabling development of;
Control and shutdown schemes Safety and regulatory requirements Start-up sequences
Operational understanding.
P&IDs form the basis for the live mimic diagrams displayed on graphical user interfaces of large industrial control systems such as SCADA and distributed control systems.
Based on STANDARD ANSI/ISA S5.1 and ISO 14617-6, the P&ID is used for the identification of measurements within the process. The identifications consist of up to 5 letters. The first identification letter is for the measured value, the second is a modifier, 3rd indicates passive/readout function, 4th - active/output function, and the 5th is the function modifier. This is followed by loop number, which is unique to that loop. For instance FIC045 means it is the Flow Indicating Controller in control loop 045. This is also known as the "tag" identifier of the field device, which is normally given to the location and function of the instrument. The same loop may have FT045 - which is the flow transmitter in the same loop.
Letter Column 1 (Measured value)
Column 2
(Modifier)
Column 3
(Readout/passive function)
Column 4
(Output/active function)
Column 5 (Function modifier)
A Analysis Alarm
B Burner, User choice User choice User choice
combustion C User's choice
(usually conductivity)
Control Close
D User's choice
(usually density) Difference Deviation
E Voltage Sensor
F Flow rate Ratio
G
User's choice (usually
gaging/gauging)
Gas Glass/gauge/viewing
H Hand High
I Current Indicate
J Power Scan
K Time, time
schedule
Time rate of
change Control station
L Level Light Low
M User's choice Middle /
intermediate N User's choice
(usually torque) User choice User choice User choice
O User's choice Orifice Open
P Pressure Point/test connection
Q Quantity Totalize/integrate Totalize/integrate
R Radiation Record Run
S Speed, frequency Safety (Non SIS
(S5.1)) Switch Stop
T Temperature Transmit
U Multivariable Multifunction Multifunction
V Vibration, Valve or
mechanical analysis
damper
W Weight, force Well or probe
X
User's choice (usually on-off valve as XV)
X-axis Accessory devices,
unclassified Unclassified Unclassified
Y Event, state,
presence Y-axis Auxiliary
devices
Z Position, dimension
Z-axis or Safety Instrumented System
Actuator, driver or unclassified final control element
For reference designation of any equipment in industrial systems the standard IEC 61346 (Industrial systems, installations and equipment and industrial products — Structuring principles and reference designations) can be applied. For the function Measurement the reference designator B is used, followed by the above listed letter for the measured variable.
Symbols of chemical apparatus and equipment
Below are listed some symbols of chemical apparatus and equipment normally used in a P&ID, according to ISO 10628 and ISO 14617.
Symbols of chemical apparatus and equipment
Pipe
Thermally insulated pipe
Jacketed pipe
Cooled or heated pipe Jacketed
mixing vessel (autoclave )
Half pipe mixing vessel
Pressurize d
horizontal vessel
Pressurize d vertical vessel
Pump
Vacuum pump or compresso r
Bag Gas bottle
Fan Axial fan,
MK, , Radial fan Dryer
Packed column
Tray
column Furnace Cooling
tower
Heat exchanger
Heat
exchanger Cooler
Plate &
frame heat exchanger Double
pipe heat exchanger
Fixed straight tubes heat exchanger
U shaped tubes heat exchanger
Spiral heat exchanger
Covered gas vent
Curved
gas vent (Air) filter Funnel or
tundish
Steam trap
Viewing glass
Pressure reducing valve
Flexible pipe
Valve Control
valve
Manual valve
Check valve
Needle valve
Butterfly valve
Diaphrag
m valve Ball valve
COGENERATION:
Need for Cogeneration: Thermal power plants are a major source of electricity supply in India.
The conventional method of power generation and supply to the customer is wasteful in the sense that only about a third of the primary energy fed into the power plant is actually made available to the user in the form of electricity (Figure 7.1). In conventional power plant, efficiency is only 35% and remaining 65% of energy is lost. The major source of loss in the conversion process is the heat rejected to the surrounding water or air due to the inherent constraints of the different thermodynamic cycles employed in power generation. Also further losses of around 10–15% are associated with the transmission and distribution of electricity in the electrical grid.
Principle of Cogeneration: Cogeneration or Combined Heat and Power (CHP) is defined as the sequential generation of two different forms of useful energy from a single primary energy source, typically mechanical energy and thermal energy. Mechanical energy may be used either to drive an alternator for producing electricity, or rotating equipment such as motor, compressor, pump or fan for delivering various services. Thermal energy can be used either for direct process applications or for indirectly producing steam, hot water, hot air for dryer or chilled water for process cooling. Cogeneration provides a wide range of technologies for application in various domains of economic activities. The overall efficiency of energy use in cogeneration mode can be up to 85 per cent and above in some cases.
For example in the scheme shown in Figure, an industry requires 24 units of electrical energy and 34 units of heat energy. Through separate heat and power route the primary energy input in power plant will be 60 units (24/0.40). If a separate boiler is used for steam generation then the fuel input to boiler will be 40 units (34/0.85). If the plant had cogeneration then the fuel input will be only 68 units (24+34)/0.85 to meet both electrical and thermal energy requirements.
It can be observed that the losses, which were 42 units in the case of, separate heat and power has reduced to 10 units in cogeneration mode. Along with the saving of fossil fuels, cogeneration also allows to reduce the emission of greenhouse gases (particularly CO2 emission). The production of electricity being on-site, the burden on the utility network is reduced and the transmission line losses eliminated. Cogeneration makes sense from both macro and micro perspectives. At the macro level, it allows a part of the financial burden of the national power utility to be shared by the private sector; in addition, indigenous energy sources are conserved.
At the micro level, the overall energy bill of the users can be reduced, particularly when there is a simultaneous need for both power and heat at the site, and a rational energy tariff is practiced in the country.
Technical Options for Cogeneration: Cogeneration technologies that have been widely commercialized include extraction/back pressure steam turbines, gas turbine with heat recovery boiler (with or without bottoming steam turbine) and reciprocating engines with heat recovery boiler.
Steam Turbine Cogeneration systems: The two types of steam turbines most widely used are the backpressure and the extraction. Another variation of the steam turbine topping cycle cogeneration system is the extraction-back pressure turbine that can be employed where the end- user needs thermal energy at two different temperature levels. The full-condensing steam turbines are usually incorporated at sites where heat rejected from the process is used to generate power. The specific advantage of using steam turbines in comparison with the other prime movers is the option for using a wide variety of conventional as well as alternative fuels such as coal, natural gas, fuel oil and biomass. The power generation efficiency of the demand for electricity is greater than one MW up to a few hundreds of MW. Due to the system inertia, their operation is not suitable for sites with intermittent energy demand.
Gas turbine Cogeneration Systems: Gas turbine cogeneration systems can produce all or a part of the energy requirement of the site, and the energy released at high temperature in the exhaust stack can be recovered for various heating and cooling applications (see Figure 7.4).
Though natural gas is most commonly used, other fuels such as light fuel oil or diesel can also be employed. The typical range of gas turbines varies from a fraction of a MW to around 100 MW.
Gas turbine cogeneration has probably experienced the most rapid development in the recent years due to the greater availability of natural gas, rapid progress in the technology, significant reduction in installation costs, and better environmental performance. Furthermore, the gestation period for developing a project is shorter and the equipment can be delivered in a modular manner. Gas turbine has a short start-up time and provides the flexibility of intermittent operation. Though it has a low heat to power conversion efficiency, more heat can be recovered at higher temperatures. If the heat output is less than that required by the user, it is possible to have supplementary natural gas firing by mixing additional fuel to the oxygen-rich exhaust gas to boost the thermal output more efficiently.
On the other hand, if more power is required at the site, it is possible to adopt a combined cycle that is a combination of gas turbine and steam turbine cogeneration. Steam generated from the exhaust gas of the gas turbine is passed through a backpressure or extraction-condensing steam turbine to generate additional power. The exhaust or the extracted steam from the steam turbine provides the required thermal energy.
Reciprocating Engine Cogeneration Systems: Also known as internal combustion (I. C.) engines, these cogeneration systems have high power generation efficiencies in comparison with other prime movers. There are two sources of heat for recovery: exhaust gas at high temperature and engine jacket cooling water system at low temperature (see Figure 7.5). As heat recovery can be quite efficient for smaller systems, these systems are more popular with smaller energy consuming facilities, particularly those having a greater need for electricity than thermal energy and where the quality of heat required is not high, e.g. low pressure steam or hot water.
Though diesel has been the most common fuel in the past, the prime movers can also operate with heavy fuel oil or natural gas. These machines are ideal for intermittent operation and their performance is not as sensitive to the changes in ambient temperatures as the gas turbines. Though the initial investment on these machines is low, their operating and maintenance costs are high due to high wear and tear.
UNIT – II
MEASUREMENTS IN POWER PLANTS
Drum level measurement:
Drum level is critical for safety and reliability. Inaccurate drum level control can result in safety issues and equipment damage. High levels can cause water carryover that lowers heat transfer efficiency and possibly damages downstream equipment such as steam turbines. Low levels expose tubes to excessive heat, resulting in tube damage and unplanned shutdown. Drum level measurement is not as simple as it might appear. Typical challenges include the need for high-pressure and high-temperature equipment, the fact that density and dielectric (DC) of water and steam vary as pressure and temperature change, and that the control ranges across a small span. Another issue is the shrink and swell phenomenon. As steam demand decreases, drum pressure increases, which compresses entrained steam bubbles and can cause the drum level to appear to decrease even though it actually increases. Conversely, as steam demand increases, drum pressure decreases, and the gas bubbles expand, often causing the drum level to appear to increase. To help compensate for shrink and swell, boiler control engineers employ three- element control strategies that simultaneously look at steam flow, the rate feed water is flowing to the steam drum and the water level in the steam drum. In addition, compensation for pressure and temperature must be made either at the level instrument or in the computer control system.
Redundant drum level measurements are recommended for safety and reliability, and because a steam drum can be uneven because of irregular heating over time, redundantly measuring on the front and back is often preferred. Another best practice is to use different measurement technologies for measurement redundancy. Figure depicts one way to obtain measurement redundancy by combining differential pressure (DP) and guided wave radar (GWR) level technologies.
Drum level measurement redundancy is best achieved by using different instruments such as both DP and GWR.
GWR can be especially advantageous in obtaining a reliable drum measurement for cases in which the level is continuously swinging. The separate measurement chamber used with GWR can dampen the effects of load swings and shrink/swell to a degree. GWR measures the time of flight of an electromagnetic pulse. It is independent of density, but steam DC can cause up to 20 percent error and varies with pressure changes. For this reason, compensation must be made for DC when using this level technology. Compensation can be accomplished in the computer controls, but obtaining a DC value for what the GWR sees is often difficult. A more direct approach is to work with a GWR device that carries out this compensation internally. Called Dynamic Vapor Compensation (DVC), it works by inserting a fixed reflective object in the path of the radar waves, well above any expected liquid level (see Figure 4). The GWR compares the measured distance to the reflector with its known distance to create a compensation value that it applies to all readings. Because it determines this correction value continuously, it corrects measurement errors under all conditions and reduces the error rate to less than 2 percent.
Oxygen measurement: The flue gas oxygen measurement at the back end of a boiler is arguably the most critical parameter used by the combustion control strategy. Managing oxygen concentration in boiler exhaust gases is important for maintaining safety and thermal efficiency.
If oxygen content is too low, the combustion process will generate excess emissions or a potentially hazardous combustible mixture that is a risk for explosion. High excess oxygen results in heat loss and possibly additional carryover that can foul tubes in the generating sections of the boiler. To support an optimal combustion control strategy an in situ oxygen analyzer — a probe inserted directly into the flue gas duct without the need for a sampling system — should be used.
The probe should typically be located in the middle of the duct on the boiler outlet after the generating bank and economizer but before the air heater (see Figure). On larger boilers, challenges caused by tramp air and/or flue gas stratification can be encountered. Tramp air infiltration may occur on older units, causing oxygen readings to appear higher than they actually are in the furnace. When this happens, maintenance should be completed to eliminate air leakage to the best degree possible such that a relatively accurate oxygen reading is possible.
Stratification results when flue gas flow is not even across the exit duct, a situation that is not uncommon during the normal operation of bigger boilers. When this is encountered, a manual duct traverse with a handheld meter should be performed to determine the best location for measurements, and multiple oxygen probes should be considered. The latest generation of oxygen meters is equipped with functionality such as online calibration capability, calibration diagnostics, and plugged diffuser/filter alarms (for boilers with fly ash or other particulate in the flue gas). These features are beneficial in keeping the important oxygen measurement device fully operational to the highest degree possible.
Fig: Flue gas stratification in the boiler exit duct may require an off-center position for the oxygen probe or the use of multiple
Air flow measurement: Boiler air flow measurement is often a challenge because of the physical arrangement of fans and ductwork. Ducts often have odd geometries and many turns, with dampers, expansion joints, internal restrictions, conditioning vanes and service access doors. Often internal restrictions are not even documented. For traditional air flow instruments, specifications typically call for extended straight upstream and downstream sections of duct with no bends, expanders, dampers or obstructions in front of the measurement point. On many units, this length of straight run cannot be found, and simply installing the instruments can be a challenge. Measurements may be needed in thin wall or fiberglass ducts, and there may be little clearance on the outside of the ducts. In such installations where the physical constraints are quite different from what a traditional flow meter would like to see, a good choice for the application is often an averaging Pitot tube (see Figure).
Fig: Averaging Pitot tube instrument with direct-mount transmitter and pressure/temperature compensation
The averaging Pitot tube mounts easily in all shapes of duct, can provide a good measurement across a wide load range, has low permanent pressure loss and has a relatively low
installed cost. These devices can simultaneously measure differential pressure, static pressure and temperature to calculate dynamically compensated mass flow in real-time and, perhaps most important, can be calibrated in place for unusual duct arrangements and where limited straight run is available (see Figure ). To calculate an optimal K factor (or flow coefficient), inline flow calibration is used if the duct is irregular or a disturbance upstream of the flow element occurs.
This involves sampling the flow at multiple points and under varying flow rates using a single- point Pitot tube. Using this technique, the true nature of the flow profile can be determined, and a reliable air flow measurement (typically, accurate to about 2 percent with good repeatability) can be obtained where it is needed on the boiler.
Fig: Air flow measurement in a short transition duct with ports to allow in-line calibration during setup
Fuel flow measurement: The approach to optimizing combustion is fundamentally a drive toward achieving mass balance between fuel and oxygen, so fuel measurements should be of the mass flow type. An important question to answer when selecting instruments for fuel flow is simply, what varies? If process variables are all nearly constant, volumetric flow measurement is the least expensive choice, and it can be a good one. However, changes in the rate of fuel flow, temperature, pressure or heating value require a meter that is able to address these changes or one that is relatively insensitive to them. Each variation may induce errors in volumetric meters used on gaseous fuels. Pressure changes will be present in nearly every fuel measurement because of pipe-friction-induced pressure loss between the regulator and the meter, regulator droop and barometric variation. When fuel pressure and temperature changes are the primary cause of variation, external compensation can be added to the flow meter to improve its accuracy.
A better option is to utilize multivariable mass transmitters that compensate for changing pressure, temperature or flow rate at the instrument. Some boilers, however, are fueled with process gas, waste gas, or whatever may be a least-cost fuel at a point in time. Since the heating value of such fuels can vary over a wide range, a direct mass Coriolis flow measurement is typically best in this situation. All types of mass flow meters improve turndown, which helps when the boiler experiences wide load swings. In addition, any changes in feedwater temperature
will require corresponding changes in firing rate. Flow measurement generally involves weighing trade-offs between a number of factors. Other issues that commonly influence meter selection and installation method include meter pressure loss (because fuel is often delivered to the boiler at low pressure), available straight run, and of course, lifecycle economic factors.
Knowing the fuel mass rate means knowing the rate at which energy (Btu/calories) is being delivered to the burners, which in turn determines the amount of air required. This makes it easier to control combustion, monitor boiler efficiency and monitor plant energy use, even with compressible fuel. Further, it makes environmental reporting easier.
Fig: DVC works by inserting a fixed reflective object in the path of the radar waves, well above any expected liquid level. The GWR compares the measured distance to the reflector with its known distance to create a compensation value that it then applies to all readings.
Steam drum level measurement
Steam drum level measurement with a differential pressure transmitter can be a tricky business when the pressure is higher than for "low" pressure steam. What happens is that as the temperature rises, the density of water drops while at the same time that of steam rises. To
compound the problem, the wet leg temperature is not well defined and its density is a third variable. A technical way around the wet leg problem is to use the following level capture apparatus. fig.. The constant condensation in the top connection maintains a constant influx of hot water at equilibrium with the steam. This maintains the heat and ensures both wet leg and measurement sections are at the same temperature (that of the water in the steam drum), below the apparatus, the two impulse lines are in close contact and therefore at the same temperature.
Whatever the density of the water is, it is the same in both legs and cancels out in the differential measurement.
UNIT III
ANALYSERS IN POWER PLANTS
The measurement methods of the oxygen analyzers currently available in the industry can be classified into the following categories.
1. Zirconia Type Measurement System 2. Paramagnetic Type
3. Optical Type
4. Electrochemical Type
Since each of the measurement methods has its advantages and disadvantages, it is important to select an oxygen analyzer of an appropriate method for your application and usage. The following describes an overview of each of the measurement methods and their advantages and disadvantages.
(1) Zirconia type measurement system: Concentration cell system A solid electrolyte like zirconia exhibits conductivity of oxygen ions at high temperature.
As shown in the figure, when porous platinum electrodes are attached to both sides of the zirconia element to be heated up and gases of different partial oxygen concentrations are brought into contact with the respective surfaces of the zirconia, the device acts as an oxygen concentration cell. This phenomenon causes an electromotive force to be generated between both electrodes according to Nernst’s equation. And it is proportional oxygen concentration.
Advantages:
Can be directly installed in a combustion process such as a boiler’s flue and requires no sampling system, and response is faster.
Disadvantages:
If the sample gas contains a flammable gas, a measurement error occurs (combustion exhaust gas causes almost no problem because it is completely burned).
(2) Zirconia type measurement system: Limiting Current type
As shown in the figure below, if the flow of oxygen into the cathode of a zirconia element heated to high temperature is limited, there appears a region where the current becomes constant even when the applied voltage is increased. This limited current is proportional to the oxygen concentration.
Advantages:
Capable of measuring trace oxygen concentration.
Calibration is required only on the span side (air).
If the sample gas contains a flammable gas, a measurement error occurs.
Disadvantages:
The presence of dust causes clogging of the gas diffusion holes on the cathode side; a filter must be installed in a preceding stage.
(3) Magnetic type measurement system: Paramagnetic system
This is one of the methods utilizing the paramagnetic property of oxygen. When a sample gas contains oxygen, the oxygen is drawn into the magnetic field, thereby decreasing the flow rate of auxiliary gas in stream B. The difference in flow rates of the two streams, A and B, which is caused by the effect of flow restriction in stream B, is proportional to the oxygen concentration of the sample gas. The flow rates are determined by the thermistors and converted into electrical signals, the difference of which is computed as an oxygen signal.
Advantages:
Capable of measuring flammable gas mixtures that cannot be measured by a zirconia oxygen analyzer.
Because there is no sensor in the detecting section in contact with the sample gas, the paramagnetic system can also measure corrosive gases.
Among the magnetic types, the paramagnetic system offers a faster response time than other systems.
Among the magnetic types, the paramagnetic system is more resistant to vibration or shock than other systems.
Disadvantages:
Requires a sampling unit corresponding to the sample gas properties or applications.
(4) Optical type: Tunable Diode Laser measurement system
Tunable Diode Laser (or TDL) measurements are based on absorption spectroscopy. The True Peak Analyzer is a TDL system and operates by measuring the amount of laser light that is absorbed (lost) as it travels through the gas being measured. In the simplest form a TDL analyzer consists of a laser that produces infrared light, optical lenses to focus the laser light through the gas to be measured and then on to a detector, the detector, and electronics that control the laser and translate the detector signal into a signal representing the gas concentration.
Advantages:
Capable of measuring a number of near infrared absorbing gases in difficult process applications.
Capability of measuring at very high temperature, high pressures and under difficult conditions (corrosive, aggressive, high particulate service).
Most applications are measured in-situ, reducing installation and maintenance costs.
Disadvantages:
The installation of the flange is necessary for both sides of the process.
Advantages:
The detecting system can be made compact; this measurement system is available in portable or transportable form.
Relatively inexpensive in comparison with oxygen analyzers of other measurement systems.
UNIT- IV
CONTROL LOOPS IN BOILER
Steam drum: The steam drum is a key component in natural, forced and combined circulation boilers. The functions of a steam drum in a subcritical boiler are:
• Mix fresh feedwater with the circulating boiler water.
• Supply circulating water to the evaporator through the downcomers.
• Receive water/steam mixture from risers.
• Separate water and steam.
• Remove impurities.
• Control water chemical balance by chemical feed and continuous blowdown.
• Supply saturated steam
• Store water for load changes (usually not a significant water storage)
• Act as a reference point for feed water control
Steam drum principle: The steam drum principle is visualized in figure. Feedwater from the economizer enters the steam drum. The water is routed through the steam drum sparger nozzles, directed towards the bottom of the drum and then through the downcomers to the supply headers.
This recovery boiler operates by natural circulation. This means that the difference in specific gravity between the downcoming water and uprising water / vapor mixture in the furnace tubes induces the water circulation. Drum internals help to separate the steam from the water. The larger the drum diameter, the more efficient is the separation. The dimensioning of a steam drum is mostly based on previous experiences. A drawing of a steam drum cross-section is shown in figure.
Water and steam in a steam drum travel in opposite directions. The water leaves the bottom of the drum to the downcomers and the steam exits the top of the drum to the superheaters. Normal water level is below the centerline of the steam drum and the residence time is normally between 5 and 20 seconds. A basic feature for steam drum design is the load rate, which is based on previous experiences. It is normally defined as the produced amount of steam (m3 /h) divided by the volume of the steam drum (m3). Calculated from the residence time in the steam drum, the volumetric load rate can be about 200 for a residence time of almost 20 seconds in the pressure of about 80 bar. The volumetric load rate increases when the pressure decreases having its maximum value of about 800. As can be thought from the units, the size of the steam drum can be calculated based on these values.
Steam separation: The steam/water separation in the steam drum is also based on the density difference of water and steam. It is important to have a steady and even flow of water/steam mixture to the steam drum. This is often realized with a manifold (header) designed for partitioning of the flow. There are different kinds of devices for water separation such as plate baffles for changing the flow direction, separators based on centrifugal forces (cyclones) and also steam purifiers like screen dryers (banks of screens) and washers. . The separation is usually carried out in several stages. Common separation stages are primary separation, secondary separation and drying. Figure shows a drawing of the steam drum and its steam separators. One typical dryer construction is a compact package of corrugated or bent plates where the water/steam mixture has to travel a long way through the dryer. One other possibility is to use wire mesh as a material for dryer. The design of a dryer is a compromise of efficiency and drain ability - at the same time the dryer should survive its lifetime with no or minor maintenance. A typical operational problem related to steam dryers is the deposition of impurities on the dryer material and especially on the free area of the dryer (holes).
In this particular steam drum, the primary separators are cyclones (figure). These enable the rising steam/water mixture to swirl, which causes the heavier water to drop out of the cyclones and thus let the lighter steam rise above and out of the cyclones. The steam, which is virtually free of moisture at this point, continues on through the secondary separators (dryers), which are called demisters. Demisters are bundles of screens that consist of many layers of tightly bundled wire 4 mesh. Demisters remove and capture any remaining droplets that may have passed through the cyclones. The water that condenses from the demisters is re-circulated through the boiler’s circulation process.
Steam purity and quality Impurity damages impurities in steam causes deposits on the inside surface of the tubes. This impurity deposit changes the heat transfer rate of the tubes and causes the superheater to overheat (CO3 and SO4 are most harmful). The turbine blades are also sensitive for impurities (Na+ and K are most harmful).
The most important properties of steam regarding impurities are :
• Steam quality, Water content: percent by weight of dry steam or moisture in the mixture
• Solid contents, Steam purity: parts per million of solids impurity in the steam quality There are salts dissolved in feedwater that need to be prevented from entering the superheater and thereby into the turbine. Depending on the amount of dissolved salt, some impurity deposition can occur on the inner surfaces of the turbine or on the inner surface of superheater tubes as well. Steam cannot contain solids (due to its gaseous form), and therefore the water content of steam defines the possible level of impurities. The water content after the evaporator (before superheaters) should be << 0.01 %- wt (percent by weight) to avoid impurity deposition on the inner tube surfaces. If the boiler in question is a high subcritical-pressure or supercritical
boiler, the requirements of the steam purity are higher (measured in parts per billion). Steam purity The solid contents are a measure of solid particles (impurities) of the steam. The boiler water impurity concentration, solid contents after the steam drum and moisture content after the steam drum are directly connected: e.g. If the boiler water impurity concentration is 500 ppm and the moisture level in the steam (after the boiler) 0,1 %, the solids content in the steam (after the boiler) is 500 ppm * 0,1 % = 0,5 ppm. Continous blowdown When water is circulated within the steam generating circuits, large amounts are recirculated, steam leaves the drum and feedwater is added to replace the exiting steam. This causes the concentration of solid impurities to build up.
To continuously remove the cumulative amounts of concentrated solids, a sparger the length of the drum is situated below the centerline. The continuous blowdown piping is used to blow the accumulations out of the drum and into the "continuous blowdown tank".
Sampling is done to properly set the rate of blowdown based upon allowable amounts of identified solids. A photograph of the blowdown piping in the recovery boiler is shown in figure . [Andritz] Steam drum placement Natural circulation boilers In natural circulation boilers the steam drum should be placed as high as possible in the boiler room because the height difference between the water level in the steam drum and the point where water begins its evaporation in the boiler tubes, defines the driving force of the circuit. The steam drum is normally placed above the boiler. Controlled circulation and once-through boilers. Shows photos from the installation process of the recovery boiler steam drum. For controlled circulation and once- through boilers the steam drum can be placed more freely, because their circulation is not depending on the place of the steam drum (pump-based circulation). This is a reason why controlled circulation and once-through boiler have been preferred in e.g. boiler modernizations, when the biggest problem is usually lack of space. Installation of steam drums (Andritz). Other aspects of steam drum design
Inside the steam drum there are also different kinds of auxiliary devices for smooth operation of the drum. The ends of feedwater pipes are placed below the drum water level and must be arranged so that the cold-water flow will not touch directly the shell of the drum to avoid thermal stresses. The water quality is maintained on one hand by chemical feed lines, which bring water treatment chemicals into the drum, and on the other hand by blowdown pipes which remove certain portion of the drum water continuously or at regular intervals. A dry-box can be placed before the removal pipe for steam. It consists of a holed or cone-shaped plate construction allowing a smooth flow distribution to a steam dryer.
Feedwater system This chapter describes the feedwater system part of the power plant process prior the boiler, i.e. between the condenser (after turbine) and the economizer. The feedwater system supplies proper feedwater amount for the boiler at all load rates. The parameters of the feedwater are temperature, pressure and quality. The feedwater system supplies also spray water for spray water groups in superheaters and reheaters. The feed water system consists of a feed water tank, feed water pump(s) and (if needed) highpressure water preheaters.
